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| EOG > SEC Filings for EOG > Form 10-Q on 29-Jul-2008 | All Recent SEC Filings |
29-Jul-2008
Quarterly Report
Overview
EOG Resources, Inc., together with its subsidiaries (EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Canada, offshore Trinidad, the United Kingdom North Sea and China. EOG operates under a consistent business and operational strategy that focuses predominantly on achieving a strong reinvestment rate of return, drilling internally generated prospects, delivering long-term production growth and maintaining a strong balance sheet.
Operations. EOG's effort to identify plays with larger reserve potential has proven a successful supplement to its base development and exploitation program in the United States and Canada. EOG continues to drill numerous wells in large acreage plays, which in the aggregate are expected to contribute substantially to EOG's natural gas and crude oil production. Production in the United States and Canada accounted for approximately 86% of total company production in the first six months of 2008 as compared to 82% in the same period of 2007. For the first six months of 2008, crude oil and natural gas liquids production accounted for approximately 17% of total company production as compared to 14% for the same period of 2007. Based on current trends, EOG expects its production profile for the remainder of 2008 to be similar to the first six months of 2008. EOG's major producing areas are in New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.
In the first six months of 2008, EOG's Trinidad operations realized higher prices for natural gas sales as compared to the same period of 2007. This increase was due to higher ammonia, methanol and liquefied natural gas prices as certain of EOG's contracts provide for prices which are either entirely or partially dependent upon the prices of these commodities. In the second quarter of 2008, EOG decided to relinquish its rights to Block Lower Reverse "L" (LRL) resulting in an impairment of $20 million.
In addition to EOG's ongoing production from the Valkyrie and Arthur Fields in the United Kingdom North Sea, EOG is evaluating development plans for its Columbus prospect in the Central North Sea Block 23/16f. A phased development and alternative export routes are being considered and a development plan decision is expected in early 2009.
On July 1, 2008, EOG acquired rights under a Petroleum Contract covering the Chuanzhong Block exploration area in Sichuan Basin, Sichuan Province, The People's Republic of China from ConocoPhillips. The acquisition includes production of approximately 8 million cubic feet equivalent per day, net, on 130,000 acres.
EOG continues to evaluate other select natural gas and crude oil opportunities outside the United States and Canada primarily by pursuing exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified.
Capital Structure. One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 13% at June 30, 2008 compared to 14% at December 31, 2007. During the first six months of 2008, EOG funded $2.5 billion in exploration and development and other property, plant and equipment expenditures, paid $52 million in dividends to common and preferred stockholders, repaid $38 million of debt and paid $5 million for the redemption of all remaining shares of its outstanding 7.195% Fixed Rate Cumulative Senior Perpetual Preferred Stock primarily by utilizing cash provided from its operating activities and proceeds from the sale of its Appalachian properties. Cash on hand increased to $108 million at June 30, 2008 from $54 million at December 31, 2007. Management continues to assess price forecast and demand trends for 2008 and believes that operations and capital expenditure activity can be funded with cash from operating activities.
EOG's 2008 budget for exploration and development and other property, plant and equipment expenditures is approximately $4.8 billion, excluding acquisitions. United States and Canada natural gas drilling activity continues to be a key component of these expenditures. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer EOG incremental exploration and/or production opportunities. Management continues to believe that EOG currently has one of the strongest prospect inventories in EOG's history.
Results of Operations
The following review of operations for the three and six months ended June 30, 2008 and 2007 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included with this Quarterly Report on Form 10-Q.
Three Months Ended June 30, 2008 vs. Three Months Ended June 30, 2007
Net Operating Revenues. During the second quarter of 2008, net operating revenues decreased $35 million, or 3%, to $1,033 million from $1,068 million for the same period of 2007. Total wellhead revenues for the second quarter of 2008, which are revenues generated from sales of natural gas, crude oil, condensate and natural gas liquids, increased $860 million, or 86%, to $1,865 million from $1,005 million for the same period of 2007. During the second quarter of 2008, EOG recognized a loss on mark-to-market commodity derivative contracts of $843 million compared to a net gain of $44 million for the same period of 2007.
Wellhead volume and price statistics for the three-month periods ended June 30, 2008 and 2007 were as follows:
Three Months Ended
June 30,
2008 2007
Natural Gas Volumes (MMcfd) (1)
United States 1,139 960
Canada 215 232
Trinidad 217 250
United Kingdom 12 22
Total 1,583 1,464
Average Natural Gas Prices ($/Mcf) (2)
United States $ 10.36 $ 6.74
Canada 9.42 6.70
Trinidad 3.64 2.04
United Kingdom 9.95 4.35
Composite 9.31 5.90
Crude Oil and Condensate Volumes (MBbld) (1)
United States 35.4 23.4
Canada 2.6 2.4
Trinidad 3.2 4.0
United Kingdom - 0.1
Total 41.2 29.9
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States $ 117.60 $ 61.38
Canada 112.55 60.08
Trinidad 113.29 75.16
United Kingdom 114.40 68.82
Composite 116.94 63.15
Natural Gas Liquids Volumes (MBbld) (1)
United States 14.2 10.4
Canada 0.9 1.1
Total 15.1 11.5
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States $ 63.62 $ 45.35
Canada 66.39 42.30
Composite 63.78 45.04
Natural Gas Equivalent Volumes (MMcfed) (3)
United States 1,437 1,163
Canada 236 253
Trinidad 236 274
United Kingdom 12 23
Total 1,921 1,713
Total Bcfe (3) 174.8 155.8
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(1) Million cubic feet per day or thousand barrels per day, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3) Million cubic feet equivalent per day or billion cubic feet equivalent, as
applicable; includes natural gas, crude oil, condensate and natural gas liquids.
Natural gas
equivalents are determined using the ratio of 6.0 thousand cubic feet of
natural gas to 1.0 barrel of crude oil, condensate or natural gas liquids.
Wellhead natural gas revenues for the second quarter of 2008 increased $555 million, or 71%, to $1,341 million from $786 million for the same period of 2007. The increase was due to a higher composite average wellhead natural gas price ($491 million) and increased natural gas deliveries ($64 million). The composite average wellhead price for natural gas increased 58% to $9.31 per million cubic feet (Mcf) for the second quarter of 2008 from $5.90 per Mcf for the same period of 2007.
Natural gas deliveries increased 119 MMcfd, or 8%, to 1,583 MMcfd for the second quarter of 2008 from 1,464 MMcfd for the same period of 2007. The increase was primarily due to higher production in the United States (179 MMcfd), partially offset by decreased production in Trinidad (33 MMcfd), Canada (17 MMcfd) and the United Kingdom (10 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (142 MMcfd) and the Rocky Mountain area (40 MMcfd), partially offset by decreased production due to the February 2008 sale of the Appalachian assets (17 MMcfd). The decline in Trinidad was primarily due to decreased deliveries as a result of plant shutdowns due to maintenance activities (35 MMcfd), partially offset by increased deliveries to Atlantic LNG Train 4 (ALNG) (5 MMcfd).
Wellhead crude oil and condensate revenues for the second quarter of 2008 increased $265 million, or 155%, to $437 million from $172 million for the same period of 2007. The increase was due to a higher composite average wellhead crude oil and condensate price ($201 million) and increased wellhead crude oil and condensate deliveries ($64 million). The composite average wellhead crude oil and condensate price for the second quarter of 2008 increased 85% to $116.94 per barrel from $63.15 per barrel for the same period of 2007. The increase in deliveries was primarily due to increased production in North Dakota.
Natural gas liquids revenues for the second quarter of 2008 increased $41 million, or 86%, to $88 million from $47 million for the same period of 2007. The increase was due to a higher composite average price ($26 million) and increased deliveries ($15 million). The composite average natural gas liquids price for the second quarter of 2008 increased 42% to $63.78 per barrel from $45.04 per barrel for the same period of 2007. The increase in deliveries primarily reflects increased production in the Fort Worth Basin Barnett Shale Play.
As a result of increasing natural gas and crude oil prices, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $843 million for the second quarter of 2008 compared to a net gain of $44 million for the same period of 2007. During the second quarter of 2008, the cash outflow related to settled natural gas and crude oil financial price swap contracts was $138 million compared to the net cash inflow related to settled natural gas and crude oil financial price swap contracts of $19 million for the same period of 2007.
Operating and Other Expenses. For the second quarter of 2008, operating expenses of $790 million were $187 million higher than the $603 million incurred in the second quarter of 2007. The following table presents the costs per Mcfe for the three-month periods ended June 30, 2008 and 2007:
Three Months Ended
June 30,
2008 2007
Lease and Well $ 0.79 $ 0.79
Transportation Costs 0.36 0.24
Depreciation, Depletion and Amortization (DD&A) 1.80 1.67
General and Administrative (G&A) 0.35 0.30
Interest Expense, Net 0.05 0.07
Total Per-Unit Costs(1) $ 3.35 $ 3.07
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(1) Total per-unit costs do not include exploration costs, dry hole costs, impairments and taxes other than income.
The primary factors impacting per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the three months ended June 30, 2008 compared to the same period of 2007 are set forth below.
Lease and well expenses include expenses for EOG-operated properties, as well as
expenses billed to EOG from other operators where EOG is not the operator of a
property. Lease and well expenses can be divided into the following categories:
costs to operate and maintain EOG's crude oil and natural gas wells, the cost of
workovers and lease and well administrative expenses. Operating and maintenance
expenses include, among other things, pumping services, salt water disposal,
equipment repair and maintenance, compression expense, lease upkeep and fuel and
power. Workovers are costs of operations to restore or maintain production from
existing wells.
Each of these categories of costs individually fluctuate from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.
Lease and well expenses of $139 million for the second quarter of 2008 increased $16 million from $123 million for the same prior year period primarily due to higher operating and maintenance expenses in the United States ($13 million) and higher lease and well administrative expenses ($9 million), partially offset by lower operating and maintenance expenses in Canada ($5 million).
Transportation costs represent costs incurred directly by EOG from third-party carriers associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees, fuel costs and transportation fees.
Transportation costs of $63 million for the second quarter of 2008 increased $26 million from $37 million for the same prior year period primarily due to increased production and costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale Play ($10 million) and the Rocky Mountain area ($11 million) to downstream markets.
DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells, reserve revisions (upward or downward) primarily related to well performance, and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from quarter to quarter.
DD&A expenses of $315 million for the second quarter of 2008 increased $56 million from the same prior year period primarily due to increased production in the United States ($49 million), increased DD&A rates in the United States ($5 million) and Canada ($4 million) and unfavorable changes in the Canadian exchange rate ($4 million), partially offset by decreased production in Canada ($3 million) and the United Kingdom ($2 million).
G&A expenses of $62 million for the second quarter of 2008 were $14 million higher than the same prior year period primarily due to higher employee-related costs ($13 million).
Interest expense, net of $9 million for the second quarter of 2008 decreased $2 million compared to the same prior year period primarily due to higher capitalized interest ($3 million).
Exploration costs of $60 million for the second quarter of 2008 increased $18 million from the same prior year period primarily due to increased geological and geophysical expenditures in the United States ($15 million) and higher employee-related costs ($3 million).
Impairments include amortization of unproved leases, as well as impairments under Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144), which requires an entity to compute impairments to the carrying value of long-lived assets based on future cash flow analysis. Impairments of $49 million for the second quarter of 2008 increased $28 million from $21 million for the same prior year period primarily due to SFAS No. 144 related impairment in Trinidad as a result of EOG's relinquishment of its rights to LRL ($20 million) and increased amortization of unproved leases in the United
States ($5 million) and Canada ($4 million). Under SFAS No. 144, EOG recorded impairments of $24 million and $6 million for the second quarter of 2008 and 2007, respectively.
Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are determined based on wellhead revenues and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.
Taxes other than income for the second quarter of 2008 increased $33 million to $95 million (5.1% of wellhead revenues) from $62 million (6.2% of wellhead revenues) for the same prior year period primarily due to an increase in severance/production taxes as a result of increased wellhead revenues in the United States. The decline in taxes other than income as a percentage of wellhead revenues primarily reflects higher wellhead revenues combined with a slight decline in non-revenue based taxes.
Income tax provision of $69 million for the second quarter of 2008 decreased $90 million compared to the same prior year period due primarily to decreased pretax income. The net effective tax rate for the second quarter of 2008 decreased to 28% from 34% for the same prior year period primarily as a result of tax benefits related to the impairment of LRL.
Six Months Ended June 30, 2008 vs. Six Months Ended June 30, 2007
Net Operating Revenues. During the first six months of 2008, net operating revenues increased $193 million, or 10%, to $2,133 million from $1,940 million for the same period of 2007. Total wellhead revenues for the first six months of 2008 increased $1,388 million, or 73%, to $3,298 million from $1,910 million for the same period of 2007. During the first six months of 2008, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $1,313 million compared to a net gain of $4 million for the same period of 2007.
Wellhead volume and price statistics for the six-month periods ended June 30, 2008 and 2007 were as follows:
Six Months Ended
June 30,
2008 2007
Natural Gas Volumes (MMcfd)
United States 1,112 938
Canada 215 227
Trinidad 224 251
United Kingdom 15 26
Total 1,566 1,442
Average Natural Gas Prices ($/Mcf)
United States $ 9.23 $ 6.55
Canada 8.42 6.57
Trinidad 3.76 2.42
United Kingdom 9.89 5.04
Composite 8.34 5.81
Crude Oil and Condensate Volumes (MBbld)
United States 33.0 22.6
Canada 2.5 2.5
Trinidad 3.4 4.2
United Kingdom - 0.1
Total 38.9 29.4
Average Crude Oil and Condensate Prices ($/Bbl)
United States $ 105.78 $ 57.75
Canada 101.41 55.88
Trinidad 99.92 67.32
United Kingdom 96.84 59.61
Composite 104.97 58.96
Natural Gas Liquids Volumes (MBbld)
United States 15.5 10.0
Canada 0.9 1.1
Total 16.4 11.1
Average Natural Gas Liquids Prices ($/Bbl)
United States $ 60.19 $ 41.40
Canada 61.52 39.39
Composite 60.26 41.20
Natural Gas Equivalent Volumes (MMcfed)
United States 1,403 1,134
Canada 236 248
Trinidad 244 276
United Kingdom 15 27
Total 1,898 1,685
Total Bcfe 345.4 305.0
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Wellhead natural gas revenues for the first six months of 2008 increased $862 million, or 57%, to $2,378 million from $1,516 million for the same period of 2007. The increase was due to a higher composite wellhead natural gas price ($723 million) and increased natural gas deliveries ($139 million). The composite average wellhead price for natural gas increased 44% to $8.34 per Mcf for the first six months of 2008 from $5.81 per Mcf for the same period of 2007.
Natural gas deliveries increased 124 MMcfd, or 9%, to 1,566 MMcfd for the first six months of 2008 from 1,442 MMcfd for the same period of 2007. The increase was due to higher production in the United States (174 MMcfd), partially offset by decreased production in Trinidad (27 MMcfd), Canada (12 MMcfd) and the United Kingdom (11 MMcfd). The increase in the United States was primarily attributable to increased production in Texas (137 MMcfd), the Rocky Mountain area (30 MMcfd), Mississippi (13 MMcfd) and Kansas (6 MMcfd), partially offset by decreased production due to the February 2008 sale of the Appalachian assets (12 MMcfd). The decline in Trinidad was primarily due to decreased deliveries as a result of plant shutdowns due to maintenance activities (24 MMcfd) and a decrease in overall contractual demand (11 MMcfd), partially offset by increased deliveries to ALNG (8 MMcfd).
Wellhead crude oil and condensate revenues for the first six months of 2008 increased $429 million, or 138%, to $740 million from $311 million for the same period of 2007. The increase was due to a higher composite average wellhead crude oil and condensate price ($324 million) and increased wellhead crude oil and condensate deliveries ($105 million). The composite average wellhead crude oil and condensate price increased 78% to $104.97 per barrel for the first six months of 2008 from $58.96 per barrel for the same period of 2007. The increase in deliveries was primarily due to increased production in North Dakota.
Natural gas liquids revenues for the first six months of 2008 increased $97 million, or 118%, to $180 million from $83 million for the same period of 2007. The increase was due to a higher composite average price ($57 million) and increased deliveries ($40 million). The composite average natural gas liquids price for the first six months of 2008 increased 46% to $60.26 per barrel from $41.20 per barrel for the same period of 2007. The increase in deliveries primarily reflects increased production in the Fort Worth Basin Barnett Shale Play.
As a result of increasing natural gas and crude oil prices, EOG recognized a loss on mark-to-market financial commodity derivative contracts of $1,313 million for the first six months of 2008 compared to a net gain of $4 million for the same period of 2007. During the first six months of 2008, the net cash outflow related to settled natural gas and crude oil financial price swap contracts was $115 million compared to the net cash inflow related to settled natural gas and crude oil financial price swap contracts of $66 million for the same period of 2007.
Operating and Other Expenses. For the first six months of 2008, operating expenses of $1,510 million were $374 million higher than the $1,136 million incurred in the same period of 2006. The following table presents the costs per Mcfe for the six-month periods ended June 30, 2008 and 2007:
Six Months Ended
June 30,
2008 2007
Lease and Well $ 0.79 $ 0.75
Transportation Costs 0.36 0.23
DD&A 1.77 1.65
G&A 0.33 0.30
Interest Expense, Net 0.06 0.06
Total Per-Unit Costs(1) $ 3.31 $ 2.99
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(1) Total per-unit costs do not include exploration costs, dry hole costs, impairments and taxes other than income.
The primary factors impacting per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net for the six months ended June 30, 2008 compared to the same period of 2007 are set forth below.
Lease and well expenses of $271 million for the first six months of 2008 were $44 million higher than the same prior year period primarily due to higher operating and maintenance expenses in the United States ($30 million) and higher lease and well administrative expenses ($16 million).
Transportation costs of $125 million for the first six months of 2008 increased $55 million from $70 million for the same prior year period primarily due to increased production and costs associated with marketing arrangements to transport production from the Fort Worth Basin Barnett Shale Play ($26 million) and the Rocky Mountain area ($19 million) to downstream markets.
DD&A expenses of $612 million for the first six months of 2008 increased $108 . . .
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